Apparatus and System for Swing Adsorption Processes Related Thereto

ABSTRACT

Provided are apparatus and systems for performing a swing adsorption process. This swing adsorption process may involve passing streams through adsorbent bed units to remove contaminants, such as water, from the stream. As part of the process, the adsorbent bed unit is purged with a purge stream that is provided from the overhead of the demethanizer. The configuration integrates a PPSA dehydration system with a cryogenic recovery system.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No.62/213,267 filed Sep. 2, 2015, entitled “Apparatus and System for SwingAdsorption Processes Related Thereto”, the entirety of which isincorporated herein by reference.

Additionally, it is noted that this application is related to U.S.Provisional Application No. 62/213,262 filed Sep. 2, 2015, entitled“Apparatus and System for Swing Adsorption Processes Related Thereto;”U.S. Provisional Application No. 62/213,270 filed Sep. 2, 2015, entitled“Apparatus and System for Combined Temperature and Pressure SwingAdsorption Processes Related Thereto” and U.S. Provisional ApplicationNo. 62/213,273 filed Sep. 2, 2015, entitled “Apparatus and System forSwing Adsorption Processes Related Thereto.”

FIELD

The present techniques relate to a system associated with an enhancedswing adsorption process. In particular, the system relates to a swingadsorption process for the dehydration of a feed stream utilizingadsorbent beds which may be integrated with recovery equipment.

BACKGROUND

Gas separation is useful in many industries and can typically beaccomplished by flowing a mixture of gases over an adsorbent materialthat preferentially adsorbs one or more gas components, while notadsorbing one or more other gas components. The non-adsorbed componentsare recovered as a separate product.

One particular type of gas separation technology is swing adsorption,such as temperature swing adsorption (TSA), pressure swing adsorption(PSA), partial pressure purge swing adsorption (PPSA), rapid cyclepressure swing adsorption (RCPSA), rapid cycle partial pressure swingadsorption (RCPPSA), and not limited to but also combinations of thefore mentioned processes, such as pressure and temperature swingadsorption. As an example, PSA processes rely on the phenomenon of gasesbeing more readily adsorbed within the pore structure or free volume ofan adsorbent material when the gas is under pressure. That is, thehigher the gas pressure, the greater the amount of readily-adsorbed gasadsorbed. When the pressure is reduced, the adsorbed component isreleased, or desorbed from the adsorbent material.

The swing adsorption processes (e.g., PSA and TSA) may be used toseparate gases of a gas mixture because different gases tend to fill themicropore of the adsorbent material to different extents. For example,if a gas mixture, such as natural gas, is passed under pressure througha vessel containing an adsorbent material that is more selective towardscarbon dioxide than it is for methane, at least a portion of the carbondioxide is selectively adsorbed by the adsorbent material, and the gasexiting the vessel is enriched in methane. When the adsorbent materialreaches the end of its capacity to adsorb carbon dioxide, it isregenerated in a PSA process, for example, by reducing the pressure,thereby releasing the adsorbed carbon dioxide. The adsorbent material isthen typically purged and repressurized. Then, the adsorbent material isready for another adsorption cycle.

The swing adsorption processes typically involve one or more adsorbentbed units, which include adsorbent beds disposed within a housingconfigured to maintain fluids at various pressures for different stepsin an adsorption cycle within the unit. These adsorbent bed unitsutilize different packing material in the bed structures. For example,the adsorbent bed units utilize checker brick, pebble beds or otheravailable packing. As an enhancement, some adsorbent bed units mayutilize engineered packing within the bed structure. The engineeredpacking may include a material provided in a specific configuration,such as a honeycomb, ceramic forms or the like.

Further, various adsorbent bed units may be coupled together withconduits and valves to manage the flow of fluids. Orchestrating theseadsorbent bed units involves coordinating the cycles for each adsorbentbed unit with other adsorbent bed units in the system. A complete PSAcycle can vary from seconds to minutes as it transfers a plurality ofgaseous streams through one or more of the adsorbent bed units.

While conventional glycol absorption processes for dehydration of feeds,such as natural gas, are established and low cost processes, glycolabsorption does not provide the level of dehydration required forcertain recovery processes, such as cryogenic processing of natural gas,for example, to recover natural gas liquids (NGLs). For example, thewater content of glycol dehydrated natural gas is relatively low (e.g.,between 100 parts per million molar (ppm) and 200 ppm) at typical fielddehydration specifications, but has to be reduced to less than 1 ppm, oreven less than 0.1 ppm, for cryogenic processing.

Conventional dehydration of natural gas streams for subsequent cryogenicprocessing is accomplished using a TSA molecular sieve adsorptionprocess. In the TSA molecular sieve adsorption process, the natural gasflows through molecular sieve adsorbent beds that extract the water fromthe gas in the stream. Several adsorbent beds are arranged in parallelto provide one or more molecular sieve adsorbent beds performing theadsorption step (e.g., adsorbing water from the stream), while one ormore of the other molecular sieve adsorbent beds are performingregeneration steps (e.g., offline for regeneration to remove adsorbedcontaminants from the adsorbent bed). When the molecular sieve adsorbentbed is almost saturated, the molecular sieve adsorbent bed is placedinto a regeneration step (e.g., taken offline) and a portion of the drygas product stream is heated to about 500° F. (260° C.) in a firedheater and directed through the molecular sieve adsorbent bed to raisethe temperature and desorb the water from the molecular sieve adsorbentbed. The wet regeneration gas (e.g., gas with the desorbed water fromthe bed) is then cooled outside the bed to condense out the water andthe gas is recycled into the feed stream upstream of the dehydrationsystem. Unfortunately, for typical NGL recovery plants, such as acryogenic NGL recovery plants, the molecular sieve adsorbent bedsrequire large high pressure vessels and involve large volumes of gas andadsorbent material. As the TSA molecular sieve adsorption processoperates at feed stream pressure, the units involve high pressures,contain a large inventory of adsorbent material, are heavy, have a largefootprint, and are costly to operate. Also, the duration of the thermalswing cycle is two or more hours as the adsorption front progressesthrough the majority of the molecular sieve adsorbent bed's length. TheTSA molecular sieve adsorption process also requires a regeneration gasfired heater that uses significant amounts of fuel and requires a largefootprint due to the safety spacing requirements for fired elements.

Conventionally, following its regenerating of the wet adsorbent beds,the wet regeneration gas is recycled to the feed stream upstream of thedehydration system or used as process plant fuel. To avoid excessiverecycle, the volume of the dry gas that can be used for regeneration islimited to a small percentage of the feed stream volume, typically lessthan ten percent. With a relatively low volume of regeneration gas andthe need to nearly completely dehydrate the adsorbent bed duringregeneration, a high regeneration temperature of about 500° F. (260° C.)or more is needed to completely regenerate the molecular sieve adsorbentbeds during each cycle. Even when the regeneration gas is limited to500° F. (260° C.), the temperature of the regeneration gas caneventually cause hydrothermal degradation of the adsorbent particles andcoke formation within the bed leading to deactivation, which is furtherincreased with higher temperatures of the purge stream. Additionally,the use of a fired heater in a natural gas plant requires increasedequipment spacing for risk mitigation, which is particularly costly inan offshore facility.

As another approach, a PSA molecular sieve adsorption process may beused for the process. This approach uses a low flow stream of purge gasat a low pressure to regenerate the molecular sieve adsorbent beds.Unfortunately, this process includes recycle compression for typicalnatural gas dehydration applications. As obtaining high regeneration gastemperatures is less costly than recycle compression, the PSA molecularsieve adsorption process is more costly than the TSA molecular sieveadsorption process noted above.

Accordingly, there remains a need in the industry for apparatus,methods, and systems that provide enhancements to the processing of feedstreams with adsorbent beds, which may be integrated with recoveryequipment. The present techniques provide enhancements by utilizing PPSAprocesses to regenerate adsorbent beds at lower pressure andtemperatures than those utilized in conventional molecular sieve TSA andPSA approaches. The present techniques overcomes the drawbacks ofconventional molecular sieve TSA and PSA approaches by using largerpurge gas volumes (e.g., ten to twenty times greater than inconventional molecular sieve TSA and PSA approaches). Further, a needremains for an approach that does not involve the use of purge gasesheated to higher temperatures (e.g., at above 500° F. (260° C.)) or theuse of fired heaters.

SUMMARY OF THE INVENTION

In one or more embodiments, the present techniques include a cyclicalswing adsorption process for removing contaminants from a gaseous feedstream. The process comprising: a) performing one or more adsorptionsteps, wherein each of the adsorption steps comprises passing a gaseousfeed stream at a feed pressure and feed temperature through an adsorbentbed unit to remove one or more contaminants from the gaseous feed streamand to form a product stream that is passed to a cryogenic recoverysystem including a demethanizer; b) performing one or moredepressurization steps, wherein the pressure of the adsorbent bed unitis reduced by a predetermined amount with each successivedepressurization step; c) performing one or more purge steps, whereineach of the purge steps comprises passing a purge stream through theadsorbent bed unit in a counter flow direction relative to the flow ofthe gaseous feed stream to form a purge product stream, wherein thepurge stream comprises at least a portion of a demethanizer overheadstream from the demethanizer; d) performing one or morere-pressurization steps, wherein the pressure within the adsorbent bedunit is increased with each re-pressurization step by a predeterminedamount with each successive re-pressurization step; and e) repeating thesteps a) to d) for at least one additional cycle. The purge stream maycomprise at least 20 volume % of the demethanizer overhead stream or maycomprise at least 50 volume % of the demethanizer overhead stream.

In another embodiment, a system for removing contaminants from a gaseousfeed stream is described. The system may include one or more adsorbentbed units and a cryogenic recovery system in fluid communication withthe one or more adsorbent bed units. The one or more adsorbent bed unitsmay each be configured to separate contaminants from a gaseous feedstream and to output a product stream, wherein the gaseous feed streamis provided at a feed temperature. Also, the cryogenic recovery systemin fluid communication with the one or more adsorbent bed units may beconfigured to receive the product stream and pass at least portion ofthe product stream to a demethanizer to separate the at least a portionof the product stream into a final product stream and a demethanizeroverhead stream. Further, a purge stream may be passed through the oneor more adsorbent bed units and may comprise at least a portion of thedemethanizer overhead stream.

BRIEF DESCRIPTION OF THE FIGURES

The foregoing and other advantages of the present disclosure may becomeapparent upon reviewing the following detailed description and drawingsof non-limiting examples of embodiments.

FIG. 1 is a three-dimensional diagram of the swing adsorption systemwith six adsorbent bed units and interconnecting piping in accordancewith an embodiment of the present techniques.

FIG. 2 is a diagram of a portion of an adsorbent bed unit havingassociated valve assemblies and manifolds in accordance with anembodiment of the present techniques.

FIG. 3 is a diagram of a conventional molecular sieve adsorption systemfor dehydration of a feed stream to form a cryogenic NGL recoverystream.

FIG. 4 is an exemplary diagram of the integration of a PPSA dehydrationsystem with a cryogenic NGL recovery system in accordance with anembodiment of the present techniques.

FIG. 5 is an exemplary chart associated with the configuration in FIG. 4in accordance with an embodiment of the present techniques.

FIGS. 6A, 6B, 6C and 6D are exemplary diagrams associated with theconfiguration in FIG. 4 in accordance with an embodiment of the presenttechniques.

FIG. 7 is an exemplary diagram of the integration of a PPSA dehydrationsystem with a cryogenic CFZ recovery system in accordance with anembodiment of the present techniques.

DETAILED DESCRIPTION OF THE INVENTION

Unless otherwise explained, all technical and scientific terms usedherein have the same meaning as commonly understood by one of ordinaryskill in the art to which this disclosure pertains. The singular terms“a,” “an,” and “the” include plural referents unless the context clearlyindicates otherwise. Similarly, the word “or” is intended to include“and” unless the context clearly indicates otherwise. The term“includes” means “comprises.” All patents and publications mentionedherein are incorporated by reference in their entirety, unless otherwiseindicated. In case of conflict as to the meaning of a term or phrase,the present specification, including explanations of terms, control.Directional terms, such as “upper,” “lower,” “top,” “bottom,” “front,”“back,” “vertical,” and “horizontal,” are used herein to express andclarify the relationship between various elements. It should beunderstood that such terms do not denote absolute orientation (e.g., a“vertical” component can become horizontal by rotating the device). Thematerials, methods, and examples recited herein are illustrative onlyand not intended to be limiting.

As used herein, “stream” refers to fluid (e.g., solids, liquid and/orgas) being conducted through various equipment. The equipment mayinclude conduits, vessels, manifolds, units or other suitable devices.

As used herein, volume percent is based on standard conditions. Thestandard conditions for a method may be normalized to the temperature of0° C. (e.g., 32° F.) and absolute pressure of 100 kiloPascals (kPa) (1bar).

As used herein, “conduit” refers to a tubular member forming a channelthrough which fluids or the other materials are conveyed. The conduitmay include one or more of a pipe, a manifold, a tube or the like.

The present techniques relate to a swing adsorption process (e.g., arapid cycle process) for the deep dehydration of a feed stream (e.g.,natural gas) utilizing rapidly cycled adsorbent beds. The presenttechniques integrate rapid cycle partial pressure purge swing adsorption(PPSA) process for dehydration of a feed stream (e.g., a natural gasstream) with downstream recovery equipment (e.g., a cryogenic NaturalGas Liquid (NGL) recovery process). The residue gas from the downstreamrecovery equipment, such as a demethanizer overhead stream from a NGLrecovery process, is used in the dehydration process as a purge gas toregenerate the adsorbent bed. The purge stream may be used to recoverwater from the adsorbent bed and may be configured to mix with residuesales gas (e.g., demethanizer overhead stream). Beneficially, in such aconfiguration, no regeneration gas has to be recycled to upstream of thedehydration process or used as fuel.

In contrast to conventional approaches, the present techniques utilizePPSA to dehydrate the adsorbent bed. As a result, the purge gas is notgenerated by other means, such as gas furnaces and the like. The purgestream may be utilized to provide cost and safety benefits, along withoperational enhancements. For example, the purge stream may lessenhydrothermal degradation of the adsorbent and lessen coke formation.Further, the present techniques may be less expensive compared toconventional TSA molecular sieve systems and have a smaller footprint byusing adsorbent beds rather than conventional TSA molecular sievedehydration.

As one enhancement, the present techniques provide the purge outputstream from the adsorbent bed from the purge step to pipeline sales gasafter passing through the adsorbent bed unit. The purge output stream isprovided to pipeline sales gas because the pipeline sales gas productspecifications are typically less stringent than cryogenic processingfeed gas specifications. Thus, water that has been removed forsubsequent downstream processing (e.g., cryogenic processing to remove aportion of the hydrocarbons heavier than methane) may be returned to thenatural gas sales gas stream, which is referred to as sales gas, afterthe recovery (e.g., NGL recovery) without adverse effects. Theconfiguration uses substantially all or the entire residue gas streamfrom the NGL plant as purge gas for the purge gas stream, which may bethe demethanizer overhead stream. As a result, the heating or pressurereduction and recompression of the purge stream (e.g., regeneration gas)may not be required. Further, by lessening the temperature of theadsorbent bed heating during the regeneration step or desorption step,the reliance on the fired heater is eliminated for steady state ornormal operations, which reduces capital investment and processfootprint. Also, the configuration lessens coke formation within theadsorbent beds and hydrothermal degradation of the adsorbent materialsthat challenge conventional TSA molecular sieve adsorption processes.

Also, the present techniques may also include various pressures for thefeed stream and the purge stream. For example, the feed pressure may bebased on the preferred adsorption feed pressure, which may be in therange from 400 pounds per square inch absolute (psia) to 1,400 psia, orin the range from 600 psia to 1,200 psia. Also, the purge pressure maybe based on the preferred adsorbent purge pressure, which may be in therange from 200 psia to 800 psia, in the range from 400 psia to 600 psia.

As another enhancement, the present techniques may provide dehydrationthrough the use of a rapid cycle swing adsorption process, such as arapid cycle PPSA process. While the swing capacity per weight of theadsorbent bed may be less than conventional TSA molecular sievedehydration, without the requirement for complete drying of theadsorbent bed (e.g., making the quantity of adsorbent required larger),the use of rapid cycles lessens the adsorbent quantity as compared toconventional TSA molecular sieve dehydration in that the requiredadsorbent quantity is ten to more than one hundred times smaller thanconventional TSA molecular sieve dehydration. Also, it may not berequired that the purge stream used on the adsorbent bed completelydries the feed end of the adsorbent bed.

In the present techniques, the product end of the adsorbent bed ismaintained nearly dry (e.g., the water loading for the region near theproduct end is less than 1 mole per kilogram (mol/kg), is less than 0.5mol/kg, or is less than 0.1 mol/kg), but is it is not essential to fullydry the feed end of the adsorbent bed. The feed end or feed side is theend of the adsorbent bed that the feed stream initially enters, whilethe product end is the end of the adsorbent bed opposite from the feedend and where the feed stream exits the adsorbent bed. The loading levelof water may be lower on the feed side of the adsorbent bed during thepurge step, but the length of adsorbent bed that contains water may bereduced during the purge step. For example, an adsorbate loaded regionmay be a specific portion of the adsorbent bed from the feed end of theadsorbent bed to 10% of the bed length, from the feed end of theadsorbent bed to 40% of the bed length or from the feed end of theadsorbent bed to 75% of the bed length. Utilizing only a portion of thebed length ensures that the product end of the bed remains rigorouslydry and enables extremely low product water concentrations. Further,maintaining a significant portion of the product end of the bed dryprovides flexibility for non-uniformity of gas passage channels inembodiments where a structured adsorbent, such as a monolith, is usedfor the adsorbent bed or adsorber structure. The product region may be aspecific portion of the adsorbent bed from the product end of theadsorbent bed to 10% of the bed length, from the product end of theadsorbent bed to 25% of the bed length or from the product end of theadsorbent bed to 40% of the bed length. The difference between the totaladsorbent bed water loading during the purge step and during theadsorption step is the basis of the swing capacity of the process.

In one or more embodiments, the flow rate of the purge stream may beassociated with the flow rate of the demethanizer overhead stream. Thepurge stream comprises at least 20 volume % of the demethanizer overheadstream, at least 50 volume % of the demethanizer overhead stream, atleast 80 volume % of the demethanizer overhead stream or at least 95volume % of the demethanizer overhead stream. In certain embodiments,the purge stream flow rate may be substantially the same as the flowrate of the demethanizer overhead flow rate (e.g., about 100 volume %).

Further, in other embodiments, the purge stream is provided at atemperature substantially similar to the temperature of the feed stream.The purge stream temperature may be within a range from 10° F. below thefeed temperature (5.6° Celsius (C.) below the feed temperature) and 350°F. above the feed temperature (194° C. above the feed temperature),within a range from 10° F. below the feed temperature (5.6° C. below thefeed temperature) and 200° F. above the feed temperature (111.1° C.above the feed temperature) or within a range from 10° F. below the feedtemperature (5.6° C. below the feed temperature) and 50° F. above thefeed temperature (27.8° C. above the feed temperature). As anotherexample, the purge stream temperature may be within a range from 25° F.below the feed temperature (13.9° C. below the feed temperature) and350° F. above the feed temperature (194° C. above the feed temperature),within a range from 25° F. below the feed temperature (13.9° C. belowthe feed temperature) and 200° F. above the feed temperature (111.1° C.above the feed temperature) or within a range from 25° F. below the feedtemperature (13.9° C. below the feed temperature) and 50° F. above thefeed temperature (27.8° C. above the feed temperature). As a specificexample, the feed stream may be provided at a temperature of 86° F. andat a feed pressure of 1000 psi. The resulting purge stream may have atemperature in the range between 72° F. (22.2° C.) and 500° F. (260° C.)or below (to minimize any thermal degradation of the adsorbent bed) andpurge pressure of 436 psi, or may be at a lower pressure. As anotherexample, the feed stream may be at a pressure of about 1000 psi and atemperature of about 75° F. (23.9° C.), the purge stream may be at atemperature of about 70° F. (21.1° C.) and a pressure of about 450 psi.Another alternate example, the operating conditions may include highertemperature for the feed stream and purge stream and pressures at orbelow 1000 psi.

In other configurations, the temperature of the purge stream may besufficiently close to the feed temperature. For example, the purgetemperature may be in a range from 10° F. below the feed temperature(5.6° C. below the feed temperature) and 25° F. above the feedtemperature (13.9° C. above the feed temperature), within a range from10° F. below the feed temperature (5.6° C. below the feed temperature)and 10° F. above the feed temperature (5.6° C. above the feedtemperature), within a range from 7° F. below the feed temperature (3.9°C. below the feed temperature) and 7° F. above the feed temperature(3.9° C. above the feed temperature) or within a range from 5° F. belowthe feed temperature (2.8° C. below the feed temperature) and 5° F.above the feed temperature (2.8° C. above the feed temperature).

Also, the present techniques may be integrated into a variousconfigurations. For example, the present techniques may be utilized, butnot limited to, dehydration prior to and integrated with a cryogenicNatural Gas Liquid (NGL) recovery system, which may involve removingcontaminants to cryogenic processing feed gas specifications. Otherembodiments may include configurations that involve integration with acontrolled freeze zone (CFZ) process. For example, the configuration mayuse the adsorbent bed units to remove heavy hydrocarbons from CFZprocess, and then use the CO₂ and H₂S clean CFZ product to purge theheavy hydrocarbons off the adsorbent beds in the adsorbent bed units.Further still, other integrations may include liquefied natural gas(LNG) plant, or other such plants. Regardless, the present techniquesmay be used to treat feed streams containing excessive amounts of waterand CO₂. The present techniques may also be used to remove contaminantsto other specifications, such as cryogenic natural gas liquefactionspecifications for a cryogenic natural gas liquefaction recovery plant.

Beneficially, the present techniques provide a modular design and may beconfigured to lessen the footprint, weight, and capital expense ofprocesses to perform dehydration of feed streams (e.g., predominatelynatural gas streams) utilizing rapidly cycled adsorbent beds. Also, asthis process does not involve the use any fired heater (e.g. firedfurnaces for normal operations), the present techniques may eliminatethe use of fired heaters or high temperature heat exchanger from theprocess. The removal of such equipment is inherently safer due to theelimination of the flames along with the associated equipment and maylower fuel consumption and greenhouse gas (GHG) emissions due to lack ofcombustion in a furnace. Further, the present techniques may increaseflexibility regarding the selection of adsorbent material used in theprocess, may reduce dust formation due to monolithic adsorbent beddesign, may lessen solid waste production due to lower adsorbentquantities and/or may lessen adsorption of heavy hydrocarbons (e.g.,C₂₊) by appropriate selection of adsorbent materials. The presenttechniques may also lower impact on downstream process equipment whenswitching adsorbent beds, but utilizing spare units to provide amechanism for some of the adsorbent bed units to be removed from servicefor adsorbent bed reconditioning or other similar processes, whilecontinuing to supply the downstream processes with a steady flow of dryor cleaned feed stream.

In one or more embodiments, the present techniques can be used for anytype of swing adsorption process. Non-limiting swing adsorptionprocesses for which the present techniques may include pressure swingadsorption (PSA), vacuum pressure swing adsorption (VPSA), temperatureswing adsorption (TSA), partial pressure swing adsorption (PPSA), rapidcycle pressure swing adsorption (RCPSA), rapid cycle thermal swingadsorption (RCTSA), rapid cycle partial pressure swing adsorption(RCPPSA), as well as combinations of these processes, such as pressureand/or temperature swing adsorption. Exemplary kinetic swing adsorptionprocesses are described in U.S. Patent Application Publication Nos.2008/0282892, 2008/0282887, 2008/0282886, 2008/0282885, 2008/0282884 and2014/0013955, which are each herein incorporated by reference in theirentirety.

Adsorptive separation processes, apparatus, and systems, as describedabove, are useful for development and production of hydrocarbons, suchas gas and oil processing. Particularly, the provided processes,apparatus, and systems are useful for the rapid, large scale, efficientseparation of a variety of target gases from gas mixtures. Inparticular, the processes, apparatus, and systems may be used to preparefeed products (e.g., natural gas products) by removing contaminants andheavy hydrocarbons (e.g., hydrocarbons having at least two carbonatoms). The provided processes, apparatus, and systems are useful forpreparing gaseous feed streams for use in utilities, includingseparation applications. The separation applications may include dewpoint control; sweetening and/or detoxification; corrosion protectionand/or control; dehydration; heating value; conditioning; and/orpurification. Examples of utilities that utilize one or more separationapplications include generation of fuel gas; seal gas; non-potablewater; blanket gas; instrument and control gas; refrigerant; inert gas;and/or hydrocarbon recovery.

In certain embodiments, the present techniques may be used to removecontaminants from feed streams, such as acid gas from hydrocarbonstreams. Acid gas removal technology may be useful for gas reservesexhibit higher concentrations of acid gas (e.g., sour gas resources).Hydrocarbon feed streams vary widely in amount of acid gas, such as fromseveral parts per million acid gas to 90 volume percent (vol. %) acidgas. Non-limiting examples of acid gas concentrations from exemplary gasreserves include concentrations of at least: (a) 1 vol. % H₂S, 5 vol. %CO₂, (b) 1 vol. % H₂S, 15 vol. % CO₂, (c) 1 vol. % H₂S, 60 vol. % CO₂,(d) 15 vol. % H₂S, 15 vol. % CO₂, and (e) 15 vol. % H₂S, 30 vol. % CO₂.Accordingly, the present techniques may include equipment to removevarious contaminants, such as H₂S and CO₂ to desired levels. Inparticular, the H₂S may be lowered to levels less than 4 ppm, while theCO₂ may be lowered to levels less than 1.8 molar percent (%) or,preferably, less than 50 ppm.

In certain embodiments, the gaseous feed stream may predominatelycomprise hydrocarbons alone with one or more contaminants. For example,the gaseous feed stream may be a hydrocarbon containing stream havinggreater than one volume percent hydrocarbons based on the total volumeof the feed stream. Further, the gaseous feed stream may includehydrocarbons and H₂O, wherein the H₂O is one of the one or morecontaminants and the gaseous feed stream comprises H₂O in the range of50 parts per million (ppm) molar to 1,500 ppm molar; or in the range of500 ppm to 1,500 ppm molar. Moreover, the gaseous feed stream mayinclude hydrocarbons and H₂O, wherein the H₂O is one of the one or morecontaminants and the gaseous feed stream comprises H₂O in the range oftwo ppm molar to saturation levels in the gaseous feed stream. Inaddition, the gaseous feed stream comprises hydrocarbons and CO₂,wherein the CO₂ is one of the one or more contaminants and the gaseousfeed stream comprises CO₂ in the range between 0 molar percent and 5molar percent of the total volume of the gaseous feed stream or therange between 0 molar percent and 2 molar percent of the total volume ofthe gaseous feed stream.

In other embodiments, the present techniques may be used to lessen thewater content of the stream to a specific level by the swing adsorptionprocess. The specific level may be related to dew point of desiredoutput product (e.g., the water content should be lower than the watercontent required to obtain a dew point below the lowest temperature ofthe stream in subsequent process and is related to the feed pressure. Asa first approximation, and not accounting for fugacity corrections as afunction of pressure, the water concentration in ppm that yields acertain dew point varies inversely with the pressure. For example, theoutput stream from the adsorbent bed may be configured to be thecryogenic processing feed stream, which satisfies the cryogenicprocessing specifications (e.g., approximately −150° F. (−101.1° C.) dewpoint for NGL processes or approximately −60° F. (−51.1° C.) forControlled Freeze Zone (CFZ) processes. The cryogenic processing feedstream specification may include a water content in the stream (e.g.,output stream from the adsorbent bed or feed stream to the to becryogenic processing) to be in the range between 0.0 ppm and 10 ppm, inthe range between 0.0 ppm and 5.0 ppm, in the range between 0.0 ppm and2.0 ppm, or in the range between 0.0 ppm and 1.0 ppm. The resultingoutput stream from the adsorbent beds during the purge step may includea water content in the stream to be in the range between 0.0 ppm and 7pounds per standard cubic feet (lb/MSCF).

In one or more embodiment, the present techniques may be used as anintegration of a rapid cycle PPSA process for removal of contaminantsfrom a feed stream (e.g., natural gas stream) with a downstreamcryogenic NGL recovery process. For example, the configuration mayinclude an integration of PPSA in the adsorption process to remove lowlevels of CO₂ from natural gas (about 2% by volume CO₂) with a cryogenicNGL plant configured for ethane recovery. The CO₂ removal may be limitedto less than the natural gas sales gas specifications. In particular, asthe gaseous feed stream may include hydrocarbons and one or morecontaminants, such as CO₂, the CO₂ in the gaseous feed stream may beless than the quantity of one minus the molar fraction of heavyhydrocarbons in the gaseous feed stream times the sales gas CO₂ maximumconcentration specification. By way of example, if the natural gas salesgas specification is CO₂ content of 2 molar % or less, and the processremoves 10 molar % heavy hydrocarbons in the NGL plant, then the purgestream may be 10 molar % less than the original feed, which results in amaximum CO₂ content in the original feed being less than 1.8 molar % CO₂so the resulting purge stream is less than 2.0 molar % CO₂ content. Inthe cryogenic NGL plant, the demethanizer column overhead stream may beused as the purge gas to regenerate the adsorbent beds, while returningthe low levels of CO₂ to the sales gas. Further, in another example, theconfiguration may include an integration of PPSA for removal of heavyhydrocarbons from a natural gas with the Controlled Freeze Zone™ (CFZ)process for bulk CO₂ removal from natural gas. See, e.g., U.S. PatentApplication Nos. 2009/0266107 and 2010/0018248. In this configuration,the sweet gas (e.g., stream having H₂S and CO₂ removed or below desiredlevels) from the CFZ process may be used as the purge gas to regeneratethe adsorbent beds, while desorbing the heavy hydrocarbons into thesales gas stream to increase its heating value or provide a mechanismfor subsequent heavy hydrocarbon recovery. As yet another example, theconfiguration may include an integration of a cyclic gas treatingprocess for removal of a first component from a gas stream, where thefirst component may interfere with a subsequent process (e.g., a secondprocess for the removal of other components from the gas stream). Inthis configuration, a substantial portion or the entire the residue gasstream remaining after removal of the other components in the secondprocess is then returned to the first process to recover the firstcomponents into the residue gas stream. Also, no other stream may berecycled from the first process to the feed stream or to fuel.

Further, other configurations may include bypassing at least a portionof the gaseous feed stream around the swing adsorption process. In suchconfigurations, a larger amount of contaminants may be processed in thesystem. For example, if a higher CO₂ content stream has to be processedas the gaseous feed stream, then a bypass configuration may be utilizedto divert at least a portion of the gaseous feed stream around the swingadsorption process (e.g., adsorbent bed units) and recombine the bypassstream with the product stream from the swing adsorption processdownstream of the swing adsorption process and upstream of thedemethanizer. In this configuration, excess CO₂ goes with the NGLs andthe demethanizer overhead is still within the pipeline specification forCO₂.

In yet another embodiment, the present techniques may not recycle theregeneration gas to the feed stream or fuel gas. This configurationovercomes the drawbacks of conventional TSA molecular sieve adsorptionprocess and PSA molecular sieve adsorption process by permitting the useof much larger purge gas volumes. For example, the purge gas volume maybe ten to twenty times greater than in conventional TSA molecular sieveadsorption process and PSA molecular sieve adsorption process.Accordingly, the PPSA may be used to regenerate the adsorbent beds atmoderate temperatures, as noted above, and pressures and lower cost.

Further, in one or more embodiments, the present techniques may includea specific process flow to remove contaminants, such as water. Forexample, the process may include an adsorbent step and a regenerationstep, which form the cycle. The adsorbent step may include passing agaseous feed stream at a feed pressure and feed temperature through anadsorbent bed unit to separate one or more contaminants from the gaseousfeed stream to form a product stream. The feed stream may be passedthrough the adsorbent bed in a forward direction (e.g., from the feedend of the adsorbent bed to the product end of the adsorbent bed). Then,the flow of the gaseous feed stream may be interrupted for aregeneration step. The regeneration step may include one or moredepressurization steps, a purge step and one or more re-pressurizationsteps. The depressurization steps may include reducing the pressure ofthe adsorbent bed unit by a predetermined amount for each successivedepressurization step, which may be a single step and/or may be ablowdown step. The depressurization step may be provided in a forwarddirection or may preferably be provided in a countercurrent direction(e.g., from the product end of the adsorbent bed to the feed end of theadsorbent bed). The purge step may include passing a purge stream intothe adsorbent bed unit, which may be a once through purge step and thepurge stream may be provided in countercurrent flow relative to the feedstream. The output stream from the purge step may be conducted away forfuel in other equipment, such as the NGL plant, CFZ plant and/or LNGplant. Then, the one or more re-pressurization steps may be performed,wherein the pressure within the adsorbent bed unit is increased witheach re-pressurization step by a predetermined amount with eachsuccessive re-pressurization step. Then, the cycle may be repeated foradditional streams. The cycle duration may be for a period greater than1 second and less than 600 seconds, for a period greater than 2 secondand less than 300 seconds, for a period greater than 2 second and lessthan 200 seconds, or for a period greater than 2 second and less than 90seconds. The present techniques may be further understood with referenceto the FIGS. 1 to 7 below.

FIG. 1 is a three-dimensional diagram of the swing adsorption system 100having six adsorbent bed units and interconnecting piping. While thisconfiguration is a specific example, the present techniques broadlyrelate to adsorbent bed units that can be deployed in a symmetricalorientation, or non-symmetrical orientation and/or combination of aplurality of hardware skids. Further, this specific configuration is forexemplary purposes as other configurations may include different numbersof adsorbent bed units.

In this system, the adsorbent bed units, such as adsorbent bed unit 102,may be configured for a cyclical swing adsorption process for removingcontaminants from feed streams (e.g., fluids, gaseous or liquids). Forexample, the adsorbent bed unit 102 may include various conduits (e.g.,conduit 104) for managing the flow of fluids through, to or from theadsorbent bed within the adsorbent bed unit 102. These conduits from theadsorbent bed units 102 may be coupled to a manifold (e.g., manifold106) to distribute the flow of the stream to, from or betweencomponents. The adsorbent bed within an adsorbent bed unit may separateone or more contaminants from the feed stream to form a product stream.As may be appreciated, the adsorbent bed units may include otherconduits to control other fluid steams as part of the process, such aspurge streams, depressurizations streams, and the like. Further, theadsorbent bed unit may also include one or more equalization vessels,such as equalization vessel 108, which are dedicated to the adsorbentbed unit and may be dedicated to one or more step in the swingadsorption process.

As an example, which is discussed further below in FIG. 2, the adsorbentbed unit 102 may include a housing, which may include a head portion andother body portions, that forms a substantially gas impermeablepartition, an adsorbent bed disposed within the housing and a pluralityof valves (e.g., poppet valves) providing fluid flow passages throughopenings in the housing between the interior region of the housing andlocations external to the interior region of the housing. Each of thepoppet valves may include a disk element that is seatable within thehead or a disk element that is seatable within a separate valve seatinserted within the head (not shown). The configuration of the poppetvalves may be any variety of valve patterns or configuration of types ofpoppet valves. As an example, the adsorbent bed unit may include one ormore poppet valves, each in flow communication with a different conduitassociated with different streams. The poppet valves may provide fluidcommunication between the adsorbent bed and one of the respectiveconduits, manifolds or headers. The term “in direct flow communication”or “in direct fluid communication” means in direct flow communicationwithout intervening valves or other closure means for obstructing flow.As may be appreciated, other variations may also be envisioned withinthe scope of the present techniques.

The adsorbent bed comprises a solid adsorbent material capable ofadsorbing one or more components from the feed stream. Such solidadsorbent materials are selected to be durable against the physical andchemical conditions within the adsorbent bed unit 102 and can includemetallic, ceramic, or other materials, depending on the adsorptionprocess. Further examples of adsorbent materials are noted furtherbelow.

FIG. 2 is a diagram 200 of a portion of an adsorbent bed unit havingvalve assemblies and manifolds in accordance with an embodiment of thepresent techniques. The portion of the adsorbent bed unit 200, which maybe a portion of the adsorbent bed unit 102 of FIG. 1, includes a housingor body, which may include a cylindrical wall 214 and cylindricalinsulation layer 216 along with an upper head 218 and a lower head 220.An adsorbent bed 210 is disposed between an upper head 218 and a lowerhead 220 and the insulation layer 216, resulting in an upper open zone,and lower open zone, which open zones are comprised substantially ofopen flow path volume. Such open flow path volume in adsorbent bed unitcontains gas that has to be managed for the various steps. The housingmay be configured to maintain a pressure between 0 bara (bar absolute)or 0.1 bara and 100 bara within the interior region.

The upper head 218 and lower head 220 contain openings in which valvestructures can be inserted, such as valve assemblies 222 to 240,respectively (e.g., poppet valves). The upper or lower open flow pathvolume between the respective head 218 or 220 and adsorbent bed 210 canalso contain distribution lines (not shown) which directly introducefluids into the adsorbent bed 210. The upper head 218 contains variousopenings (not show) to provide flow passages through the inlet manifolds242 and 244 and the outlet manifolds 248, 250 and 252, while the lowerhead 220 contains various openings (not shown) to provide flow passagesthrough the inlet manifold 254 and the outlet manifolds 256, 258 and260. Disposed in fluid communication with the respective manifolds 242to 260 are the valve assemblies 222 to 240. If the valve assemblies 222to 240 are poppet valves, each may include a disk element connected to astem element which can be positioned within a bushing or valve guide.The stem element may be connected to an actuating means, such asactuating means (not shown), which is configured to have the respectivevalve impart linear motion to the respective stem. As may beappreciated, the actuating means may be operated independently fordifferent steps in the process to activate a single valve or a singleactuating means may be utilized to control two or more valves. Further,while the openings may be substantially similar in size, the openingsand inlet valves for inlet manifolds may have a smaller diameter thanthose for outlet manifolds, given that the gas volumes passing throughthe inlets may tend to be lower than product volumes passing through theoutlets. Further, while this configuration has valve assemblies 222 to240, the number and operation of the valves may vary (e.g., the numberof valves) based on the specific cycle being performed.

In swing adsorption processes, the cycle involves two or more steps thateach has a certain time interval, which are summed together to be thecycle time. These steps include the regeneration step of the adsorbentbed following the adsorption step or feed step using a variety ofmethods including pressure swing, vacuum swing, temperature swing,purging (via any suitable type of purge fluid for the process), andcombinations thereof. As an example, a swing adsorption cycle mayinclude the steps of adsorption, depressurization, purging, andre-pressurization. When performing the separation at high pressure,depressurization and re-pressurization (which may be referred to asequalization steps) are performed in multiple steps to reduce thepressure change for each step and enhance efficiency. In some swingadsorption processes, such as rapid cycle swing adsorption processes, asubstantial portion of the total cycle time is involved in theregeneration of the adsorbent bed. Accordingly, any reductions in theamount of time for regeneration results in a reduction of the totalcycle time. This reduction may also reduce the overall size of the swingadsorption system.

As noted above, conventional systems for dehydration is typicallyaccomplished using TSA molecular sieve adsorption processes and PSAmolecular sieve adsorption processes. The conventional systems involvemany hours of operation for the molecular sieve unit to both fill withadsorbed species (e.g., water) and to heat for desorption. As a result,the molecular sieve units are very large (e.g., are a large footprintand involve more adsorbent than the present techniques). To minimize theregeneration gas volume required and to maximize bed capacity, theadsorbent beds of the molecular sieve unit is typically dried completely(e.g., below the desired product water activity level), which utilizes apurge gas at or above about 500° F. (260° C.). In addition, theconventional approaches maintain a narrow mass transfer zone, or sharpadsorption front to maximize bed utilization, while maintaining rigorousdehydration. A schematic diagram 300 of a conventional molecular sieveadsorption system 302 integrated into a cryogenic NGL recovery system304 is shown below in FIG. 3.

As an example, FIG. 3 is a diagram 300 of a conventional molecular sieveadsorption system 302 for dehydration of a feed stream to form acryogenic NGL recovery stream for a cryogenic NGL recovery system 304.As shown in the diagram 300, various equipment, such as units 308, 312,316, 320, 322, 324 and 326 in the conventional molecular sieveadsorption system 302 and units 330, 334, 336, 340, 344, 346 and 348 incryogenic NGL recovery system 304. The systems 302 and 304 are utilizedto process an input stream in conduit 306 to produce an output stream,such as a cryogenic NGL stream in conduit 332. The cryogenic NGL streammay be provided with approximately 70 molar % of the C₂ and 100 molar %C₃₊ contained in the original feed stream to the NGL process.

For the conventional molecular sieve adsorption system 302, the unitsare utilized to perform an adsorption step and a regeneration step inprocessing the input stream into the cryogenic NGL feed stream. Theprocess begins with an input stream passing through conduit 306 tovarious units 308 and 312 during an adsorption step. The input streampasses initially into a filter 308, which is configured to remove atleast a portion of particulates and liquid droplets from the inputstream. The output stream from the filter 308 is the feed stream, whichis provided via conduit 310 to a first molecular sieve unit 312. Thefirst molecular sieve unit 312 is configure to separate additionalcontaminants, such as water from the stream. The dehydrated output fromthe first molecular sieve unit 312 is conveyed away from the firstmolecular sieve unit 312 in conduit 314. A portion of the stream inconduit 314 may be separated and utilized as a regeneration stream for asecond molecular sieve unit 316 in a regeneration step. Thisregeneration stream may be a slip stream from the output stream from thefirst molecular sieve unit 312 during the adsorption step. The remainingportion of the output stream from the first molecular sieve unit 312 isprovided to the cryogenic NGL recovery system 304 via conduit 318 as thecryogenic NGL feed stream.

For the regeneration step, the regeneration stream is passed to a firedheater unit 320, which is configured to adjust the temperature of theregeneration stream before being passed to the second molecular sieveunit 316. Then, the resulting molecular sieve regeneration stream ispassed from the second molecular sieve unit 316 to a condenser 322. Thecondenser 322 is configured to decrease the temperature of the stream toform a liquid phase in the stream. From the condenser 322, the stream ispassed to a separation unit 324, which is configured to separate theliquid phase from the vapor phase of the stream. The vapor phase ispassed as a recycle stream to a recycle compressor 326, while the liquidphase is conducted away from the process. The recycle compressor 326compresses the recycle stream from the separation unit 324 to thepressure of the input stream. The compressed recycle stream is thenmixed with the input stream and provided to a molecular sieve unitperforming the adsorption step in the process, such as first molecularsieve unit 312.

For the cryogenic NGL recovery system 304, the cryogenic NGL feed streamis provided from the conventional molecular sieve adsorption system 302via conduit 318. In the cryogenic NGL recovery system 304, the units areutilized to process the cryogenic NGL feed stream and generate acryogenic NGL output stream conducted away from the system 304 inconduit 332. The process begins by passing the cryogenic NGL feed stream(e.g., product steam from the absorbent bed unit 410) into a gas/gasexchanger unit 330 that lowers the temperature (e.g., cools) of theinlet stream by gas-gas temperature exchange with the residual gas(e.g., demethanizer overhead stream) exiting the NGL process. Then, thestream from the gas/gas exchanger unit 330 is provided to a coldseparation unit 334, which separates the stream into a first stream(e.g., a first stream containing the methane and lighter heavyhydrocarbons) and a second stream (e.g., a second stream containing theheaviest of the hydrocarbons). From the cold separation unit 334, thefirst stream is conducted toward a turboexpander unit 336, which isconfigured to expand the stream to lessen the temperature of the stream,and then the stream is passed to the demethanizer 344. A slip stream maybe separated from the first stream upstream of the turboexpander unit336, which is mixed with the second stream upstream of the subcoolerunit 340. The second stream is passed from the cold separation unit 334through a throttle valve 338 to control mixing ratios and combined withthe slip stream from the first stream. The combined stream is passed tothe subcooler unit 340 that adjusts the temperature of the stream to thedesired temperature for the demethanizer tower. From the subcooler unit340, the stream is passed through a throttle valve 342 that controls thefeed rate to the demethanizer 344. The demethanizer 344 is utilized toseparate the stream into the cryogenic NGL output stream conducted awayfrom the system 304 in conduit 332 and an overhead stream (e.g.,demethanizer overhead stream). The overhead stream is passed to thesubcooler unit 340. Then, from the subcooler unit 340, the stream ispassed to the gas/gas exchanger unit 330. From the gas/gas exchangerunit 330 the stream is passed to the compressor 346. The compressor 346compresses the stream and passes the compressed stream passes thecompressed stream to the boost compressor 348. The boost compressor 348further increases the pressure of the stream into a boost output streamthat is conducted away from the process via conduit 350. The boostoutput stream may be used for sales gas or utilized in other processes.

In this configuration, cryogenic temperatures in the demethanizer 344 bynear-isentropic expansion in a turboexpander unit 336. The work ofexpansion in the turboexpander unit 336 drives a compressor 346 topartially recompress the lean residue gas from the gas/gas exchangerunit 330. The boost compressor 348 is utilized to boost the stream(e.g., residue gas from the compressor 346) to sales pipeline exportpressure.

As an example, the input stream may be provided at a flow rate of 200million standard cubic feet per day (MSCFD), at a temperature of about86° F. and at a pressure of about 1,176 pounds per square inch absolute(psia). The input stream may include primarily methane along with otherhydrocarbons and contaminants. In particular, the methane (C₁) may beabout 92 volume percent (vol. %), the other hydrocarbons (C₂ ⁺) may beabout 8 vol. %, and the water (H₂O) may be about 34 pounds per millionstandard cubic feet (lb/MSCF). The first molecular sieve unit 312 mayadjust the stream to form the cryogenic NGL feed stream. The cryogenicNGL feed stream may be provided at a flow rate of 200 million standardcubic feet per day (MSCFD), at a temperature of about 85° F. and at apressure of about 1,150 pounds per square inch absolute (psia). Further,the first molecular sieve unit 312 may lessen the water (H₂O) content toless than 1.0 ppm.

The regeneration stream for a second molecular sieve unit 316 may beheated in the fired heater unit 320 to increase the temperature of theregeneration stream. In particular, the regeneration stream may have aflow rate of 16 MSCFD, may be at a temperature of 550° F. (287.8° C.)and may be at a pressure of 1,150 psia. This stream may pass through thesecond molecular sieve unit 316, condenser 322 and the separation unit324. From the separation unit 324, the recycle stream may have a flowrate of 16 MSCFD, may be at a temperature of 115° F. and may be at apressure of 1,125 psia. This recycle stream may be compressed in therecycle compressor 326 to a pressure of 1 176 psia.

Further, in the cryogenic NGL recovery system 304, the cryogenic NGLfeed stream may be provided at a flow rate of 200 MSCFD, at atemperature of about 85° F. (29.4° C.) and at a pressure of about 1,150pounds per square inch absolute (psia). Further, the first molecularsieve unit 312 may lessen the water (H₂O) content to less than 0.1 ppm.The stream from the turboexpander unit 336 may be provided at a flowrate of 150 MSCFD, at a temperature of about −118° F. (−83.3° C.) and ata pressure of about 347 pounds per square inch absolute (psia). Thestream provided to the subcooler unit 340 from the demethanizer 344 maybe provided at a flow rate of 184 MSCFD, at a temperature of about −147°F. (−99.4° C.) and at a pressure of about 345 pounds per square inchabsolute (psia). Further, the stream provided from the compressor 346 tothe boost compressor 348 may be provided at a flow rate of 184 MSCFD, ata temperature of about 83° F. (28.3° C.) and at a pressure of about 436pounds per square inch absolute (psia). The stream from the boostcompressor 348 may be provided at a flow rate of 184 MSCFD, at atemperature of about 115° F. (46.1° C.) and at a pressure of about 1,175pounds per square inch absolute (psia). The stream may have a water(H₂O) content of less than 0.1 ppm.

As noted in this example, the regeneration stream (e.g., the purgestream from this process) from the fired heater unit 320 is provided atan elevated temperature of 550° F. (287.8° C.). This high temperatureregeneration stream may result in hydrothermal degradation of theadsorbent particles and coke formation within the molecular sieveadsorbent bed leading to deactivation and associated downtime.

Moreover, the particular NGL recovery process may be referred to as theGas Subcooled Process (GSP) and is suitable for ethane recoveries of upto 90 molar % of the ethane present in the feed stream. As may beappreciated, other cryogenic NGL recovery processes, such as Ortloff'sRecycle Split Vapor (RSV) and Single Column Overhead Recycle (SCORE)processes, are well known and can be employed depending on the level ofethane or propane recovery desired. Further, triethylene glycolabsorption dehydration system may also be installed upstream at fieldgathering stations or at the gas plant inlet (not shown) to lessen thefeed stream water content below saturation (e.g., about 34 lb/Mscf atconditions described in the example) and may lessen loading on the TSAdehydration system needed to meet the cryogenic processing waterspecification.

In contrast the conventional system in FIG. 3, the present techniquesprovides enhancements in the processing of feed streams with adsorbentbeds which may be integrated with recovery equipment. For example, thepresent techniques utilize PPSA processes to regenerate adsorbent bedsat lower temperatures than those utilized in conventional molecularsieve TSA process. Further, this method may be at higher purge gaspressure thus involving less additional compression than PSA approaches.Indeed, the present techniques may be configured to have the purge gaspressure near or at the sales gas pressure to further lessen anycompression. As a result, the present techniques overcomes the drawbacksof conventional molecular sieve TSA and PSA approaches by using largerpurge gas volumes, not using purge gases heated to higher temperatures(e.g., at above 500° F. (260° C.)) and not using fire heaters for thepurge step.

As an example of these enhancements, FIG. 4 is an exemplary diagram 400of the integration of a PPSA dehydration system 402 with a cryogenic NGLrecovery system 404 in accordance with an embodiment of the presenttechniques. In this configuration, the PPSA dehydration system 402 mayinclude one or more adsorbent bed units, such as the adsorbent bedsunits discussed in FIGS. 1 and 2, to perform the dehydration for theinput stream. The process may involve performing rapid cycle swingadsorption, which involves using the residue gas from a stream providedfrom the demethanizer 430 (e.g., a demethanizer overhead stream) at amoderately reduced pressure as the purge stream for the adsorbent bedunits. Also, by integrating the PPSA dehydration system 402 with acryogenic NGL recovery system 404, various enhancements are provided bysuch a configuration, which are utilized to lessen costs associated withthe process. Further, as the quantity of adsorbents varies inversely andlinearly with the cycle time, the present techniques provide adsorbentbed units and components that involve a smaller footprint as compared toconventional systems, such as the configuration noted in FIG. 3.

In this configuration, various equipment, such as units 406, 408, 410and 412 in the PPSA dehydration system 402 and units 330, 334, 336, 340,346, 348 and 430 in cryogenic NGL recovery system 404. The systems 402and 404 are utilized to process an input stream in conduit 306 toproduce an output stream, such as a cryogenic NGL stream in conduit 332.These streams may be similar to those noted in the discussion of FIG. 3.Further, while certain units may be utilized in a manner similar to thatnoted above in FIG. 3, such as units 330, 334, 336, 340, 346 and 348,this configuration includes variations on the flow path of the streamsbetween these units to provide various enhancements to the process. Inthis configuration, energy may be conserved by not using fired heatersto provide a high temperature purge gas as in the conventional molecularsieve TSA process, and substantially all of the methane in the feedstream may be recovered as sales gas.

In the PPSA dehydration system 402, the units are utilized to perform anadsorption step (e.g., a feed step) and a regeneration step inprocessing the input stream into the cryogenic NGL feed stream. Theprocess begins with an input stream passing through conduit 306 variousunits 406, 408 and 410 during an adsorption step. The input streampasses initially into a glycol contactor unit 406, which is configuredto remove at least a portion of the water from the input stream. Theoutput water content from the glycol contactor unit 406 may be adjustedto be below the water level specification for natural gas sales as allof the water fed to the adsorbent bed units may eventually be associatedwith the methane used for purging the adsorbent beds, and as the heavierhydrocarbons may have been removed, the volume of the stream may besmaller than that of the initial feed stream. Thus, the water in thestream may be at a higher concentration in the sales gas than it is atthe outlet of the glycol contactor unit 406. The output stream from theglycol contactor unit 406 is conducted to the filter unit 408, which isconfigured to remove particulates and liquid droplets from the stream.The output from the filter unit 408 is the feed stream. Then, the feedstream is conducted to the first adsorbent bed unit 410. The firstadsorbent bed unit 410 is configure to separate additional contaminants,such as water from the feed stream. For example, the first adsorbent bedunit 410 may be configured to remove a sufficient portion of the H₂Ofrom the stream, such as the water content of the exiting stream may beless than 2.0 ppm, less than 1.0 ppm or less than 0.1 ppm. Thedehydrated output from the first adsorbent bed unit 410 is conveyed awayfrom the first adsorbent bed unit 410 in conduit 414, which is thecryogenic NGL feed stream provided to the cryogenic NGL recovery system404 as the cryogenic NGL feed stream.

After the adsorption step of the swing adsorption cycle, the pressure isreduced in one or more blowdown steps. The blowdown step or steps may beperformed by flowing the stream in the same direction as the feed streamin the adsorption step, and thus the blowdown gas may have low water orother contaminant content. Thus, it is useful to pass this blowdownstream through a valve 416 to the demethanizer 430 via conduit 428.

For the purge step, the purge stream is passed in a direction counter tothe feed stream direction (e.g., a countercurrent direction) to thesecond adsorbent bed unit 412 from the compressor 346 in the cryogenicNGL recovery system 404. Then, the purge output stream from the secondadsorbent bed 412 is passed to the boost compressor 348. For thecryogenic NGL recovery system 404, the cryogenic NGL feed stream isprocessed in a similar manner, as noted above in the discussion of FIG.3. However, this configuration integrates the flow of streams with thePPSA dehydration system 402. For example, the cryogenic NGL feed streamis passed to the gas/gas exchanger unit 330 and then processed in thecold separation unit 334, turboexpander unit 336, throttle valve 338,subcooler unit 340 and throttle valve 342, as noted above. However, inthis configuration, the demethanizer 430 receives a blowdown stream froma portion of the output from the second adsorbent bed unit 412, theoutput stream from the turboexpander unit 336, and the output streamfrom the throttle valve 342. The demethanizer 430 is utilized toseparate the stream into the cryogenic NGL output stream (e.g., a finalproduct stream) conducted away from the system 404 in conduit 332 and anoverhead stream. The overhead stream is passed to the subcooler unit340, through the gas/gas exchanger unit 330 and to the compressor 346.Then, the output stream from the compressor 346 in the cryogenic NGLrecovery system 404 is passed as the purge stream through the secondadsorbent bed unit 412 in the PPSA dehydration system 402 via conduit411, as noted above. Optionally a portion of the purge stream in conduit411 may be diverted to bypass the second adsorbent bed unit 412. Thepurge output stream may be passed to the boost compressor 348 in thecryogenic NGL recovery system 404 from the second adsorbent bed unit 412in the PPSA dehydration system 402. The boost compressor 348 furtherincreases the pressure of the stream into a boost output stream that isconducted away from the process via conduit 350. The boost output streammay be used for sales gas or utilized in other processes. In otherconfigurations, the purge output stream may be provided at a pressurenear or at the sales gas pressure to further lessen compression steps.The pressure of the purge output stream may be within a range of 10% ofthe sales gas pressure of the sales gas stream in conduit 350.

This configuration utilizes a purge stream that is at lower temperaturescompared to conventional molecular sieve approaches. The adsorbent bedunits 410 and 412, which may be used in a rapid cycle swing adsorptionprocess, are regenerated in a purge step with residue gas from a streamprovided from the demethanizer 430 (e.g., a demethanizer overheadstream) at a moderately reduced pressure. In this configuration, thedemethanizer overhead stream is used as purge gas after heating andpartial recompression in the compressor 346, which is driven by theturboexpander unit 336. Depending on the NGL content of the feed streamand the extent of NGL recovery, the purge gas flow rate may be in therange between 70 volume % and 95 volume % of the feed flow rate or in arange between 90 volume % and 95 volume % of the feed flow rate. Thefeed stream may involve pressure in a range between 900 and 1,200 psia(or in a range between 1100 and 1,200 psia), while the demethanizer 430may operate at pressure in the range between 300 psia and 600 psiarange, and the purge gas pressure after the compressor 346 may be in therange between 400 psia and 600 psia. As an example, the feed streampressure may be 1,175 psia, the demethanizer may operate at a pressureof 345 psia, the purge gas pressure may be 436 psia and thus theadsorbent bed pressure swings from about 1,160 psia to 430 psia. In thisconfiguration, the purge gas temperature is similar to the feed streamtemperature because of extensive heat integration that is involved inNGL recovery plants. For example, the feed stream temperature may be atemperature of about 85° F., the demethanizer overhead stream is heatedin a subcooler unit 340 and the gas/gas exchanger from −147° F. to 83°F. by heat exchange with the dry rich gas and through the effect ofpartial recompression in the turboexpander unit 336 coupled to thecompressor 346. Thus, the adsorbent bed temperature may change smallamounts during the adsorption step and desorption step (e.g. the purgestep) of the cycle. With similar feed stream and purge stream flow ratesand adsorption step and desorption step (e.g., for a time period oftwenty-four and sixteen seconds, respectively, in a forty-eight secondcycle), the pressure swing and purge step at near constant bedtemperature is sufficient to regenerate the adsorbent bed in theadsorbent bed units.

As an example, three adsorbent beds may be used to treat 200 MSCFD ofwet feed stream, where each adsorbent bed unit has a diameter of 0.25meters (m) and a length of 0.60 m. In this example, each bed is composedof adsorbent-coated parallel channels arranged in a monolith with over2,000 channels per square inch, where each uncoated channel is 500 by500 micron in cross-section, and the channels are separated by 25.4micron steel walls and coated internally with a 60 micron layer ofporous adsorbent. In this example, the typical heat capacity of theadsorber bed was about 3.0 Joules per gram adsorbent per degree Kelvin(J/g adsorbent/K). Each adsorbent bed contains a total of about 22kilograms (kg) of adsorbent giving a total of 66 kg for the process. Inaddition, the present techniques do not require a narrow mass transferzone, thus a wide range of adsorbents can be used for rigorous waterremoval. These include but are not limited to silica gel, Zeolite 3A, 4Aand 5A.

These adsorbent bed units may be used in the configuration of FIG. 4. Inparticular, the input stream may be provided at a flow rate of 200million standard cubic feet per day (MSCFD), at a temperature of about86° F. (30° C.) and at a pressure of about 1,175 pounds per square inchabsolute (psia). The input stream may include primarily methane alongwith other hydrocarbons and contaminants. By way of example, the methane(C₁) may be about 92 volume percent (vol. %), the other hydrocarbons(C₂₊) may be about 8 vol. %, and the water (H₂O) may be about 34lb/MSCF. The stream from the glycol contactor unit 406 may be providedat a flow rate of 200 MSCFD, at a temperature of about 86° F. and at apressure of about 1,175 pounds per square inch absolute (psia). Thestream may include primarily methane and the water (H₂O) may be about 5lb/MSCF. The stream is then passed through the filter 408 and providedto the first adsorbent bed unit 410 may adjust the stream to form thecryogenic NGL feed stream. The cryogenic NGL feed stream from the firstadsorbent bed unit 410 may be provided at a flow rate of 198 MSCFD, at atemperature of about 85° F. and at a pressure of about 1,155 psia.Further, the first adsorbent bed unit 410 may lessen the water (H₂O)content to less than 1.0 ppm.

For the regeneration, the purge stream is provided to the secondadsorbent bed unit 412 may have a flow rate of 184 MSCFD, may be at atemperature of 83° F. and may be at a pressure of 436 psia. From thesecond adsorbent bed unit 412, the purge vent stream may have a flowrate of 182 MSCFD, may be at a temperature of 82° F. and may be at apressure of 424 psia, while the blowdown stream may have a flow rate of2 MSCFD, may be at a temperature of 84° F. and may be at a pressure of435 psia.

Further, in the cryogenic NGL recovery system 404, the cryogenic NGLfeed stream from the first adsorbent bed unit 410 may be provided to thegas/gas exchanger unit 330 at a flow rate of 198 MSCFD, at a temperatureof about 85° F. and at a pressure of about 1,155 psia. Further, thefirst adsorbent bed unit 410 may lessen the water (H₂O) content to lessthan 0.1 ppm. Further, the stream provided from the turboexpander unit336 to the demethanizer 430 may be provided at a flow rate of 149 MSCFD,at a temperature of about −119° F. and at a pressure of about 347 poundsper square inch absolute (psia), while the stream from the subcoolerunit 340 to the demethanizer 430 may be provided at a flow rate of 49MSCFD, at a temperature of about −119° F. and at a pressure of about 347pounds per square inch absolute (psia). From the demethanizer 430, theoverhead stream (e.g., demethanizer overhead flow rate) may be providedat a flow rate of 184 MSCFD, at a temperature of about −147° F. and at apressure of about 345 pounds per square inch absolute (psia). Further,the stream provided from the compressor 346 to the second adsorbent bedunit 412 may be provided at a flow rate of 184 MSCFD, at a temperatureof about 83° F. and at a pressure of about 436 pounds per square inchabsolute (psia). Further, the stream from the boost compressor 348 maybe provided at a flow rate of 184 MSCFD, at a temperature of about 115°F. and at a pressure of about 1,175 pounds per square inch absolute(psia). The stream may have a water (H₂O) content of less than about 5.4lb/MSCF.

In this diagram 400, the adsorbent beds are regenerated via a purge stepwith a purge stream that is from the overhead stream of the demethanizer430. The purge stream may have a composition substantially similar tothat of the overhead stream from the demethanizer 430 and be at a flowrate that is substantially similar, as well. For example, the flow rateof the purge stream may be associated with the flow rate of thedemethanizer overhead stream from the demethanizer 430. The purge streammay comprise at least 20 volume % of the demethanizer overhead stream,at least 50 volume % of the demethanizer overhead stream, at least 80volume % of the demethanizer overhead stream or at least 95 volume % ofthe demethanizer overhead stream. For example, in the configuration ofdiagram 400, the purge stream comprises the demethanizer overhead flowrate (e.g., about 100 volume %).

Further, in this configuration, the purge stream is provided at atemperature substantially similar to the temperature of the feed stream.For example, the purge stream is provided at a temperature substantiallysimilar to the temperature of the feed stream. The purge streamtemperature may be within a range from 25° F. below the feed temperature(13.9° C. below the feed temperature) and 350° F. above the feedtemperature (194° C. above the feed temperature), within a range from25° F. below the feed temperature (13.9° C. below the feed temperature)and 200° F. above the feed temperature (111.1° C. above the feedtemperature) or within a range from 25° F. below the feed temperature(13.9° C. below the feed temperature) and 50° F. above the feedtemperature (27.8° C. above the feed temperature). The purge streamtemperature may be within a range from 10° F. below the feed temperature(5.6° C. above the feed temperature) and 350° F. above the feedtemperature (194° C. above the feed temperature), within a range from10° F. below the feed temperature (5.6° C. above the feed temperature)and 200° F. above the feed temperature (111.1° C. above the feedtemperature) or within a range from 10° F. below the feed temperature(5.6° C. below the feed temperature) and 50° F. above the feedtemperature (27.8° C. above the feed temperature). In otherconfigurations, the temperature of the purge stream may be sufficientlyclose to the feed temperature. For example, the purge temperature may bein a range from 10° F. below the feed temperature (5.6° C. below thefeed temperature) and 25° F. above the feed temperature (13.9° C. abovethe feed temperature), in a range from 10° F. below (5.6° C. below thefeed temperature) the feed temperature and 10° F. above the feedtemperature (5.6° C. above the feed temperature), within a range from 7°F. below the feed temperature (3.9° C. below the feed temperature) and7° F. above the feed temperature (3.9° C. above the feed temperature) orwithin a range from 5° F. below the feed temperature (2.8° C. below thefeed temperature) and 5° F. above the feed temperature (2.8° C. abovethe feed temperature).

Beneficially, this configuration may remove any additional heatexchanger or furnace from the process flow. Further, the purge streammay be provided at lower temperature and higher volumes than otherprocesses. As the purge stream is provided at a lower temperature, itinvolves less heat than the regenerated gas in the conventional TSAprocess of FIG. 3 even through the volume of the purge stream is larger.

The enhancements of the present techniques are further illustrated bycomparing the two processes. For example, to perform the samedehydration of a feed stream, the process in the conventional molecularsieve process, as noted in FIG. 3, the purge stream temperature is 500°F. (260° C.) or higher, while the rapid cycle partial pressure purgeswing adsorption utilizes a purge stream at 83° F. (28.3° C.). Further,the present techniques utilize less adsorbent material as compared tothe conventional molecular sieve process. For example, the adsorbentutilized in the configuration of FIG. 4 is 44 kg, while the conventionalTSA molecular sieve process in FIG. 3 requires three adsorbent beds,each containing about 38,000 kg of zeolite 4A adsorbent for a total of114,000 kg of adsorbent. Thus, the conventional process is a factor of1,300 larger than the process of the present techniques. Accordingly,each of the two adsorbent bed units of the configuration of FIG. 4 has adiameter of 0.25 m and a length of 0.60 m, while the unit for theconventional TSA molecular sieve process are roughly 1.4 m in diameterand 6.7 m long. Thus, the footprint for the present techniques issignificantly less than the conventional TSA molecular sieve process.This configuration may be adjusted for different pressures,temperatures, flow rates, durations, bed counts, dimensions and weights.

In one or more embodiment, the glycol contactor unit 406 may be atri-ethylene glycol (TEG) dehydration process may be used on the inputstream at the inlet, upstream of the PPSA dehydration process. This unitmay be used to reduce the water loading of the dehydration process, andto provide the flexibility to adjust the sales gas water content. Asshown above in the example, the sales gas water content from theintegrated process may be about 5.4 lb/Mscf assuming the stream providedto the PPSA dehydration system 402 has been dehydrated in the field orat the plant inlet to 5.0 lb/Mscf. The slight increase is due to theremoval of the NGLs which causes 5 molar % to 10 molar % shrinkage ofthe sales gas volume relative to the feed stream volume, depending onthe depth of NGL recovery achieved. Thus, the glycol system can be usedto meet the sales gas specification by removing sufficient water toaccount for the shrinkage. Modeling shows that this has negligibleeffect on the economics of the integrated process.

In other embodiments, other NGL recovery processes, such as RSV andSCORE, can be integrated in a similar manner with PPSA dehydrationsystem in this configuration by using the demethanizer overhead stream(e.g., residue gas) to purge the adsorbent beds and recover the water tothe sales gas.

FIG. 5 is exemplary chart 500 associated with the configuration in FIG.4 in accordance with an embodiment of the present techniques. Thediagram 500 describes the timing and steps for an exemplary cycle of theswing adsorption process. In diagram 500, the bed pressure response 502and the bed temperature response 504 are shown along pressure axis 506in psia, the temperature axis 508 in ° F. with respect to the cycle timeaxis 510 in seconds (s) for the steps in an exemplary cycle. The cycletime is show in Table 1 below:

TABLE 1 Cycle Timing Step Time Direction Hold 4 seconds None Blowdown 8seconds Counter-flow Purge 24 seconds  Counter-flow Hold 4 seconds NoneFeed Repressurize 8 seconds Co-flow Adsorption or Feed 24 seconds Co-flow

As shown in Table 1 and the chart 500, the cycle includes performingvarious steps in specific flow directions relative to the flow of thefeed stream (e.g., co-flow is in the same direction as the feed streamand counter-flow is in the direction opposite of the feed stream throughthe adsorbent bed). For example, a hold step for four second, a blowdownstep for eight seconds, a purge step for twenty-four seconds (e.g., fromtwelve seconds into the cycle to thirty-six seconds into the cycle), asecond hold step for four seconds, a repressurize step for eight secondsand then an adsorption step for twenty-four seconds (e.g., fromforty-eight seconds into the cycle to seventy-two seconds into thecycle). The resulting duration for a single cycle in this configurationis seventy-two seconds. The temperature, as shown along the temperatureresponse 504 is relatively stable throughout the cycle, while thepressure within the adsorbent bed unit is lower during the purge andblowdown steps as compared with the adsorption step and feedrepressurize step.

FIGS. 6A, 6B, 6C and 6D are exemplary diagrams 600, 620, 640 and 660associated with the configuration in FIG. 4 in accordance with anembodiment of the present techniques. In these diagrams 600, 620, 640and 660, the cycle may include performing a hold step for four second, ablowdown step for eight seconds, a purge step for twenty-four seconds(e.g., from 12 seconds into the cycle to 36 seconds into the cycle), asecond hold step for four seconds, a repressurize step for eight secondsand then an adsorption step for twenty-four seconds (e.g., from 48seconds into the cycle to 72 seconds into the cycle). The resultingduration for a single cycle in this configuration is seventy-twoseconds. These diagrams 600 and 620 further describe water loading forthe timing of the steps in an exemplary cycle of the swing adsorptionprocess, while the diagrams 640 and 660 further describe temperature forthe timing of the steps in an exemplary cycle of the swing adsorptionprocess.

For FIG. 6A, the water loading responses 602, 604, 606 and 608 in thediagram 600 are shown along water loading axis 610 in moles per kilogram(mol/kg) with respect to the bed length axis 612 in normalized bedlength (z/L). The response 602 represents forty-eight seconds into thecycle, the response 604 represents fifty-six seconds into the cycle, theresponse 606 represents sixty-four seconds into the cycle and theresponse 608 represents seventy-two seconds into the cycle. Each ofthese responses 602, 604, 606 and 608 are the water loading at thevarious times during the adsorption step. The leading edge of theadsorption front for each of the responses 602, 604, 606 and 608 doesnot increase in the latter region of the adsorbent bed (e.g., productregion or portion near the product end). In particular, for thisexample, the product region of the adsorbent bed is the portion of theabsorbent bed from the product end to about 50% of the bed length fromthe product end of the adsorbent bed and is maintained with a waterloading for the product region less than about 1 mole per kilogram(mol/kg).

For FIG. 6B, the water loading responses 622, 624, 626 and 628 indiagram 620 are shown along water loading axis 630 in mol/kg withrespect to the bed length axis 632 in z/L. The response 622 representstwelve seconds, the response 624 represents twenty seconds, the response626 represents twenty-eight seconds and the response 628 representsthirty-six seconds and shows the progression of the water loading fromthe adsorbent bed during the purge step. As shown on this diagram 620,the water loading decreases as the purge step continues from the initialtime of twelve seconds into the cycle (e.g., response 622) to the end ofthe purge step at time of thirty-six seconds into the cycle (e.g.,response 628). For the duration of this purge step, the water loadingfor the product region, as defined in FIG. 6A, is less than about 1mol/kg.

In this configuration, the purge step removes water from the adsorbentbed. For example, the highest content of water is at the end of theadsorption step (e.g., response 608), while the lowest content of wateris at the end of the purge step (e.g., response 628). As indicated bythe responses 622, 624, 626 and 628, the swing capacity of the adsorbentbed in this cycle is a small fraction of the total bed capacity. Theextreme reduction in adsorbent bed size is due to the use of rapidcycles, as compared to conventional TSA dehydration beds, and providesan enhanced technique for dehydration, while only regenerating a portionof the total bed capacity in each regeneration cycle.

In FIG. 6C, the temperature response 642, 644, 646 and 648 in diagram640 are shown along the temperature axis 650 in ° F. with respect to thebed length axis 652 in z/L. The response 642 represents forty-eightseconds into the cycle, the response 644 represents fifty-six secondsinto the cycle, the response 646 represents sixty-four seconds into thecycle and the response 648 represents seventy-two seconds into thecycle. These responses show the progression of the temperature of theadsorbent bed during the adsorption step or feed step. As shown on thisdiagram 640, the temperature of the adsorbent bed decreases as theadsorption step continues from the initial time of forty-eight seconds(e.g., response 642) to the end of the adsorption step at time ofseventy-two seconds (e.g., response 648).

In FIG. 6D, the temperature response 662, 664, 666 and 668 in diagram660 are shown along the temperature axis 670 in ° F. with respect to thebed length axis 672 in z/L. The response 662 represents twelve secondsinto the cycle, the response 664 represents thirteen seconds into thecycle, the response 666 represents fourteen seconds into the cycle andthe response 668 represents thirty-six seconds into the cycle. Theseresponses show the progression of the temperature of the adsorbent bedduring the purge step. As shown on this diagram 660, the temperature ofthe adsorbent bed increases as the purge step continues from the initialtime of twelve seconds (e.g., response 662) to the end of the purge stepat time of thirty-six seconds (e.g., response 668).

As another example, the present techniques may include a cryogeniccontrolled freeze zone recovery system as the cryogenic recovery system.The cryogenic controlled freeze zone is a cryogenic distillation processthat separates methane from gas streams containing large amounts of CO₂.The system includes a refluxed demethanizer with a freeze zone in themiddle to facilitate freezing and re-melting of the CO₂, as is known byone skilled in the art. A demethanizer overhead stream (e.g., a cleanvapor methane stream) is obtained as the top product from thedemethanizer of the CFZ process, while a final product stream (e.g.,high pressure acid liquid product) is obtained as the bottoms product.Any heavier hydrocarbons in the feed to the CFZ recovery system are alsoremoved as the bottoms product. For this process, dehydration isnecessary upstream of the cryogenic CFZ recovery system to ensure thathydrates do not form in the cryogenic equipment. Further, in thisconfiguration, water may be removed upstream of CFZ (e.g., with a swingadsorption process or other suitable process) and heavy hydrocarbons mayalso be removed upstream of the CFZ (e.g., with a swing adsorptionprocess or other suitable process), which may lessen loss of certainhydrocarbons in the bottom product.

The dehydration of the feed stream for the cryogenic CFZ recovery systemmay the use rapid cycle swing adsorption processes and units todehydrate this stream. In the cryogenic controlled freeze zone recoverysystem, various steps may be utilized to dehydrate the stream. Forexample, the steps may be similar to the steps used in a configurationof FIG. 4. As noted above for FIG. 4, the purge stream may be at least aportion of the demethanizer overhead stream, which may be the vapormethane stream from the CFZ process in the CFZ system. This purge streammay be provided at pressures in the range between 450 psia and 650 psia.As an example of the dehydration process steps, the adsorbent bed unitis initially repressurized and then a feed stream is dehydrated in anadsorption step. Following the adsorption step, the adsorbent bed issubjected to various regeneration steps. The regeneration steps includeone or more blowdown steps, which each may lessen the pressure withinthe adsorbent bed unit and the final pressure may be slightly below thepurge pressure. Following the blowdown steps, one or more purge stepsmay be performed, wherein each purge step may be provided in a countercurrent flow direction relative to the feed stream flow direction. Thepurge stream (e.g., primarily methane stream) may remove thecontaminants from the adsorbent bed. In certain configurations, heat mayalso be added to the process to further enhance the process.

As an example of these enhancements, FIG. 7 is an exemplary diagram 700of the integration of a PPSA dehydration system 402 with a cryogenic CFZrecovery system 702 in accordance with an embodiment of the presenttechniques. In this configuration, the PPSA dehydration system 402 mayinclude one or more adsorbent bed units, such as the adsorbent bedsunits discussed in FIGS. 1 and 2, to perform the dehydration for theinput stream. The process may involve performing rapid cycle swingadsorption, which involves using the residue gas from a stream providedfrom the demethanizer 704 (e.g., a demethanizer overhead stream) at apurge pressure, within the range between 450 psia and 650 psia, forexample, as the purge stream for the adsorbent bed units. Also, byintegrating the PPSA dehydration system 402 with a cryogenic CFZrecovery system 702, various enhancements are provided by such aconfiguration, which are utilized to lessen costs associated with theprocess. Further, as the quantity of adsorbents varies inversely andlinearly with the cycle time, the present techniques provide adsorbentbed units and components that involve a smaller footprint as compared toconventional CFZ systems.

In this configuration, various equipment, such as units 406, 408, 410and 412 in the PPSA dehydration system 402 and units 704, 706 and 708 incryogenic CFZ recovery system 702, may be used in the process. Thesystems 402 and 702 are utilized to process an input stream in conduit306 to produce a final output stream, such as a cryogenic CFZ stream inconduit 710. The streams in the dehydration system 402 may be similar tothe streams noted in the discussion of FIG. 4. Further, while certainunits may be utilized in a manner similar to that noted above in FIG. 4,such as units 406, 408, 410, 348 and 412, this configuration includesvariations on the flow path of the streams between these units toprovide various enhancements to the process. In this configuration,energy may also be conserved by not using fired heaters andsubstantially all of the methane in the feed stream may be recovered assales gas.

In the PPSA dehydration system 402, the units are utilized to perform anadsorption step (e.g., a feed step) and a regeneration step inprocessing the input stream into the cryogenic CFZ feed stream. Theprocess begins with an input stream passing through conduit 306 variousunits 406, 408 and 410 during an adsorption step. The first adsorbentbed unit 410 is configure to separate additional contaminants, such aswater from the feed stream. For example, the first adsorbent bed unit410 may be configured to remove a sufficient portion of the H₂O from thestream, such as the water content of the exiting stream may be less than2.0 ppm, less than 1.0 ppm or less than 0.1 ppm. The dehydrated outputfrom the first adsorbent bed unit 410 is conveyed away from the firstadsorbent bed unit 410 in conduit 414, which is the cryogenic CFZ feedstream provided to the cryogenic CFZ recovery system 702 as thecryogenic CFZ feed stream.

In the cryogenic CFZ recovery system 702, the cryogenic CFZ feed streamis passed to the conditioning unit 704. In the conditioning unit 704,the cryogenic CFZ feed stream is conditioned and then passed throughthrottle valve 708 to the CFZ demethanizer 706. The CFZ methanizer 706includes a refluxed demethanizer with a freeze zone in the middle tofacilitate freezing and re-melting of the CO₂, as is known by oneskilled in the art. The CFZ demethanizer 706 may separate the streamfrom the throttle valve 708 into a demethanizer overhead stream, whichis a vapor stream containing primarily methane, and a final productstream, which is a high pressure acid liquid product stream. The finalproduct stream may be conducted away from the cryogenic CFZ recoverysystem 702 via conduit 710, as a product CFZ stream. The demethanizeroverhead stream may be passed to the conditioning unit 704 via conduit712, which may be conducted away to the PPSA dehydration system 402 viaconduit 714 to be used as the purge stream.

After the adsorption step of the swing adsorption cycle, the pressure isreduced in one or more blowdown steps and then one or more purge stepsare performed. The blowdown step or steps may be performed by flowingthe stream in the same direction as the feed stream in the adsorptionstep, and thus the blowdown gas may have low water or other contaminantcontent. For the purge step, the purge stream, which is at least aportion of the demethanizer overhead stream from conduit 714, may bepassed in a direction counter to the feed stream direction (e.g., acountercurrent direction) to the second adsorbent bed unit 412. Then,the purge output stream from the second adsorbent bed 412 is passed tothe boost compressor 348. Optionally a portion of the purge stream inconduit 712 or 714 may be diverted to bypass the conditioning unit 704and/or second adsorbent bed unit 412. The purge stream may remove atleast a portion of the contaminants from the adsorbent bed and beconducted away from the adsorbent bed unit 412 to the boost compressor348. The boost compressor 348 further increases the pressure of thestream into a boost output stream that is conducted away from theprocess via conduit 350. The boost output stream may be used for salesgas or utilized in other processes. In other configurations, the purgeoutput stream may be provided at a pressure near or at the sales gaspressure to further lessen compression steps. The pressure of the purgeoutput stream may be within a range of 10% of the sales gas pressure ofthe sales gas stream in conduit 350.

Further, in other embodiments, the heavy hydrocarbons from the feedstream to the CFZ process may be removed by the rapid cycle swingadsorption process. The removal of heavy hydrocarbons may involve aseparate set of adsorbent bed units or may be integrated with theadsorbent bed units represented by adsorbent bed units 410 and 412. Insuch configurations, the purge stream may utilize more of thedemethanizer overhead stream, which may also be provided at an elevatedtemperature to further enhance the process.

In one or more embodiments, the material may include an adsorbentmaterial supported on a non-adsorbent support. Non-limiting examples ofadsorbent materials may include alumina, microporous zeolites, carbons,cationic zeolites, high silica zeolites, highly siliceous orderedmesoporous materials, sol gel materials, aluminum phosphorous and oxygen(ALPO) materials (microporous and mesoporous materials containingpredominantly aluminum phosphorous and oxygen), silicon aluminumphosphorous and oxygen (SAPO) materials (microporous and mesoporousmaterials containing predominantly silicon aluminum phosphorous andoxygen), metal organic framework (MOF) materials (microporous andmesoporous materials comprised of a metal organic framework) andzeolitic imidazolate frameworks (ZIF) materials (microporous andmesoporous materials comprised of zeolitic imidazolate frameworks).Other materials include microporous and mesoporous sorbentsfunctionalized with functional groups. Examples of functional groups,which may be used for CO₂ removal, may include primary, secondary,tertiary amines and other non protogenic basic groups such as amidines,guanidines and biguanides.

In one or more embodiments, the adsorbent bed unit may be utilized toseparate contaminants from a feed stream. The method may include passinga gaseous feed stream at a feed pressure through an adsorbent bed unithaving an adsorbent contactor to separate one or more contaminants fromthe gaseous feed stream to form a product stream, wherein the adsorbentcontactor has a first portion and a second portion; interrupting theflow of the gaseous feed stream; performing a depressurization step,wherein the depressurization step reduces the pressure within theadsorbent bed unit; performing a purge step, wherein the purge stepreduces the pressure within the adsorbent bed unit and wherein the purgestep involves passing a purge stream to a mid-purge distribution zonebetween first portion and the second portion; performing are-pressurization step, wherein the re-pressurization step increases thepressure within the adsorbent bed unit; and repeating the steps a) to e)for at least one additional cycle.

Further, in one or more embodiments, the adsorbent bed unit may includean adsorbent bed that can be used for the separation of a target gasform a gaseous mixture. The adsorbent is usually comprised of anadsorbent material supported on a non-adsorbent support, or contactor.Such contactors contain substantially parallel flow channels wherein 20volume percent, preferably 15 volume percent or less of the open porevolume of the contactor, excluding the flow channels, is in poresgreater than about 20 angstroms. A flow channel is taken to be thatportion of the contactor in which gas flows, if a steady state pressuredifference is applied between the points or places at which a feedstream enters the contactor and the point or place at which a productstream leaves the contactor. In the contactor, the adsorbent isincorporated into the wall of the flow channel.

In one or more embodiments, the rapid cycle swing adsorption process inthe present techniques is a rapid cycle temperature swing adsorption(RCTSA) and a pressure swing adsorption (PSA). For example, the totalcycle times are typically less than 600 seconds, less than 300 seconds,preferably less than 200 seconds, more preferably less than 90 seconds,and even more preferably less than 60 seconds.

In view of the many possible embodiments to which the principles of thedisclosed invention may be applied, it should be recognized that theillustrative embodiments are only preferred examples of the inventionand should not be taken as limiting the scope of the invention.

What is claimed is:
 1. A cyclical swing adsorption process for removingcontaminants from a gaseous feed stream, the process comprising: a)performing one or more adsorption steps, wherein each of the adsorptionsteps comprises passing a gaseous feed stream at a feed pressure andfeed temperature through an adsorbent bed unit to remove one or morecontaminants from the gaseous feed stream and to form a product streamthat is passed to a cryogenic recovery system including a demethanizer;b) performing one or more depressurization steps, wherein the pressureof the adsorbent bed unit is reduced by a predetermined amount with eachsuccessive depressurization step; c) performing one or more purge steps,wherein each of the purge steps comprises passing a purge stream throughthe adsorbent bed unit in a counter flow direction relative to the flowof the gaseous feed stream to form a purge product stream, wherein thepurge stream comprises at least a portion of a demethanizer overheadstream from the demethanizer; d) performing one or morere-pressurization steps, wherein the pressure within the adsorbent bedunit is increased with each re-pressurization step by a predeterminedamount with each successive re-pressurization step; and e) repeating thesteps a) to d) for at least one additional cycle.
 2. The cyclical swingadsorption process of claim 1, wherein the purge stream comprises atleast 20 volume % of the demethanizer overhead stream.
 3. The cyclicalswing adsorption process of claim 1, wherein the purge stream comprisesat least 50 volume % of the demethanizer overhead stream.
 4. Thecyclical swing adsorption process of claim 1, wherein the purge streamcomprises at least 95 volume % of the demethanizer overhead stream. 5.The cyclical swing adsorption process of claim 1, wherein the purgestream is at a purge temperature within a range between 10° F. below thefeed temperature (5.6° C. below the feed temperature) and 350° F. abovethe feed temperature (194° C. above the feed temperature).
 6. Thecyclical swing adsorption process of claim 1, wherein the purge streamis at a purge temperature within a range from 10° F. below the feedtemperature (5.6° C. below the feed temperature) and 25° F. above thefeed temperature (13.9° C. above the feed temperature).
 7. The cyclicalswing adsorption process of claim 1, wherein the cycle duration isgreater than 1 second and less than 600 seconds.
 8. The cyclical swingadsorption process of claim 1, wherein the gaseous feed stream is ahydrocarbon containing stream having greater than one volume percenthydrocarbons based on the total volume of the feed stream.
 9. Thecyclical swing adsorption process of claim 1, wherein the gaseous feedstream comprises hydrocarbons and H₂O, wherein the H₂O is one of the oneor more contaminants and the gaseous feed stream comprises H₂O in therange of two parts per million molar to saturation levels in the gaseousfeed stream.
 10. The cyclical swing adsorption process of claim 1,wherein the gaseous feed stream comprises hydrocarbons and H₂O, whereinthe H₂O is one of the one or more contaminants and the gaseous feedstream comprises H₂O in the range of 50 parts per million molar to 1,500parts per million molar.
 11. The cyclical swing adsorption process ofclaim 1, wherein the gaseous feed stream comprises hydrocarbons and CO₂,wherein the CO₂ is one of the one or more contaminants and the gaseousfeed stream comprises CO₂ in the range between 0 molar percent and 5molar percent of the total volume of the gaseous feed stream.
 12. Thecyclical swing adsorption process of claim 1, wherein the gaseous feedstream comprises hydrocarbons and the one or more contaminants compriseCO₂, wherein the CO₂ in the gaseous feed stream is less than thequantity of one minus the molar fraction of heavy hydrocarbons in thegaseous feed stream times the sales gas CO₂ maximum concentrationspecification.
 13. The cyclical swing adsorption process of claim 1,wherein the feed pressure is in the range between 400 pounds per squareinch absolute (psia) and 1,400 psia.
 14. The cyclical swing adsorptionprocess of claim 1, wherein the cycle duration is greater than 2 secondsand less than 300 seconds.
 15. The cyclical swing adsorption process ofclaim 1, wherein water content in the product stream is in the rangebetween 0.0 ppm and 5.0 ppm.
 16. The cyclical swing adsorption processof claim 1, wherein the cryogenic recovery system is a cryogenic naturalgas liquids recovery system.
 17. The cyclical swing adsorption processof claim 1, wherein the cryogenic recovery system is a cryogeniccontrolled freeze zone recovery system.
 18. The cyclical swingadsorption process of claim 1, wherein the pressure of the purge outputstream is within a range of 10% of the sales gas pressure of the salesgas stream.
 19. The cyclical swing adsorption process of claim 1,wherein the adsorbent bed unit comprises an adsorbent material ofZeolite 3A, Zeolite 4A or Zeolite 5A.
 20. A system for removingcontaminants from a gaseous feed stream, the system comprising: one ormore adsorbent bed units, wherein each of the one or more adsorbent bedunits is configured to separate contaminants from a gaseous feed streamand to output a product stream, wherein the gaseous feed stream isprovided at a feed temperature; a cryogenic recovery system configuredto receive the product stream and pass at least portion of the productstream to a demethanizer to separate the at least a portion of theproduct stream into a final product stream and a demethanizer overheadstream; and wherein a purge stream is passed through the each of the oneor more adsorbent bed units and comprises at least portion of thedemethanizer overhead stream.
 21. The system of claim 20, furthercomprising: a glycol contactor unit configured to receive an inputstream and to remove at least a portion of the water from the inputstream; and a filter unit configured to receive the glycol output streamfrom the glycol contactor unit and to conduct away particulates andliquid droplets and to provide the feed stream to the one or moreadsorbent bed units.
 22. The system of claim 20, wherein the gaseousfeed stream is below saturation levels.
 23. The system of claim 20,further comprising a gas/gas exchanger unit configured to receive theproduct stream from the adsorbent bed unit and to lower the temperatureof the product stream by heat exchange with the at least portion of thedemethanizer overhead stream.
 24. The system of claim 23, furthercomprising a subcooler unit configured to receive a portion of theexchanger output stream from the gas/gas exchanger unit and to adjustthe temperature of the portion of the exchanger output stream to thedesired temperature for the demethanizer by heat exchange with the atleast portion of the demethanizer overhead stream.
 25. The system ofclaim 23, further comprising a compressor configured to receive thedemethanizer overhead stream from the gas/gas exchanger unit; increasethe pressure of the demethanizer overhead stream into a compresseddemethanizer overhead stream; and provide the compressed demethanizeroverhead stream to a regeneration adsorbent bed unit as the purgestream.
 26. The system of claim 20, wherein the cryogenic recoverysystem is a cryogenic natural gas liquids recovery system.
 27. Thesystem of claim 20, wherein the cryogenic recovery system is a cryogeniccontrolled freeze zone recovery system.